Process for removing oxygenates from hydrocarbon streams

ABSTRACT

A method of removing oxygenates from a hydrocarbon stream comprises passing a hydrocarbon stream to a caustic tower having a plurality of loops, contacting the hydrocarbon stream with a sulfided catalyst between a first loop of the plurality of loops and a second loop of the plurality of loops to produce a reaction product, passing the reaction product to the second loop, removing at least a portion of the hydrogen sulfide in the second loop of the caustic tower to produce a product stream, and separating the product stream into a plurality of hydrocarbon streams in a separation zone located downstream of the caustic tower. The hydrocarbon stream comprises hydrocarbons, oxygen containing components, and sulfur containing compounds. At least a portion of the sulfur compounds react in the presence of the sulfided catalyst to produce hydrogen sulfide in the reaction product.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

REFERENCE TO A MICROFICHE APPENDIX

Not applicable.

BACKGROUND

Crude oil and other hydrocarbons (e.g., various gas streams, coal,lignite, coke, biomass, etc.) can be converted into a variety ofproducts using various processes. Initially, the valuable components canbe separated and purified from a hydrocarbon stream, and the remainingcomponents (e.g., heavy crude fractions) can be processed using variousreactions to convert less valuable components into more valuablecomponents. Cracking is an example of one process used to convert heavyhydrocarbons into lighter hydrocarbons, or upgrade lighter componentsinto more valuable compounds. For example, olefins can be produced fromhydrocarbon feedstocks by catalytic and/or steam cracking processes.These cracking processes can upgrade various reactants and produce lightolefins such as ethylene and propylene from various feedstocks. Oxygenand oxygenates can be present in the various cracking processes throughan introduction in the feed stream, through the process (e.g., throughthe oxidation of the coke on the catalyst in a Fluid Catalytic Cracker(FCC), steam introduction in steam cracking, etc.), or the like. Theresulting oxygen and oxygenates may be removed along with othercontaminates using various downstream processes to produce any number ofsaleable product streams.

SUMMARY

In an embodiment, a method of removing oxygenates from a hydrocarbonstream comprises passing a hydrocarbon stream to a caustic tower havinga plurality of loops, contacting the hydrocarbon stream with a sulfidedcatalyst between a first loop of the plurality of loops and a secondloop of the plurality of loops to produce a reaction product, passingthe reaction product to the second loop, removing at least a portion ofthe hydrogen sulfide in the second loop of the caustic tower to producea product stream, and separating the product stream into a plurality ofhydrocarbon streams in a separation zone located downstream of thecaustic tower. The hydrocarbon stream comprises hydrocarbons, oxygencontaining components, and sulfur containing compounds. At least aportion of the sulfur compounds react in the presence of the sulfidedcatalyst to produce hydrogen sulfide in the reaction product.

In an embodiment, a system for removing oxygenates from a hydrocarbonstream comprises a caustic wash unit comprising a plurality of causticwash loops, and a hydrogenation reactor configured to receive a firstgaseous stream from a first caustic wash loop of the plurality ofcaustic wash loops and pass a second gaseous stream from thehydrogenation reactor to a second caustic wash loop of the plurality ofcaustic wash loops. The hydrogenation reactor comprises a sulfidedcatalyst.

In an embodiment, a method of removing oxygenates from a hydrocarbonstream comprises passing a hydrocarbon stream having one or morehydrocarbons, one or more oxygen containing components, and one or moreacid gas components to a first loop of a caustic tower, removing aportion of the one or more acid gas components in the first loop of thecaustic tower to produce a first product stream, passing the firstproduct stream from the first loop of the caustic tower to ahydrogenation unit, contacting the first product stream with a sulfidedcatalyst in the hydrogenation unit to produce a second product stream,passing the second product stream to a second loop of the caustic tower,and removing at least a portion of the hydrogen sulfide in the secondloop of the caustic tower to produce a third product stream. At least aportion of the one or more sulfur containing compounds reacts in thepresence of the sulfided catalyst to produce hydrogen sulfide in thereaction product.

These and other features will be more clearly understood from thefollowing detailed description taken in conjunction with theaccompanying drawings and claims.

BRIEF DESCRIPTION OF THE DRAWING

For a more complete understanding of the present disclosure, referenceis now made to the following brief description, taken in connection withthe accompanying drawings and detailed description, wherein likereference numerals represent like parts.

FIG. 1 illustrates a schematic flow diagram of a process for removingoxygen containing compounds according to an embodiment.

DETAILED DESCRIPTION

It should be understood at the outset that although illustrativeimplementations of one or more embodiments are illustrated below, thedisclosed systems and methods may be implemented using any number oftechniques, whether currently known or not yet in existence. Thedisclosure should in no way be limited to the illustrativeimplementations, drawings, and techniques illustrated below, but may bemodified within the scope of the appended claims along with their fullscope of equivalents.

The following brief definition of terms shall apply throughout theapplication:

The term “comprising” means including but not limited to, and should beinterpreted in the manner it is typically used in the patent context;

The phrases “in one embodiment,” “according to one embodiment,” and thelike generally mean that the particular feature, structure, orcharacteristic following the phrase may be included in at least oneembodiment of the present invention, and may be included in more thanone embodiment of the present invention (importantly, such phrases donot necessarily refer to the same embodiment);

If the specification describes something as “exemplary” or an “example,”it should be understood that refers to a non-exclusive example;

The terms “about” or “approximately” or the like, when used with anumber, may mean that specific number, or alternatively, a range inproximity to the specific number, as understood by persons of skill inthe art field; and

If the specification states a component or feature “may,” “can,”“could,” “should,” “would,” “preferably,” “possibly,” “typically,”“optionally,” “for example,” “often,” or “might” (or other suchlanguage) be included or have a characteristic, that particularcomponent or feature is not required to be included or to have thecharacteristic. Such component or feature may be optionally included insome embodiments, or it may be excluded.

Disclosed herein is a system and methods for removing oxygenates from ahydrocarbon stream, such as a stream from a cracking process, whichintegrates a hydrogenation unit with an acid removal unit. Thehydrogenation unit can use sulfided catalysts to handle streams withsulfur and other acid gases. The hydrogenation unit can be integratedbetween two loops of an acid removal unit such as a caustic wash tower.The integration of the hydrogenation process with the caustic wash towermay reduce the need for upstream wet-treatment processes such as a waterwash, an amine unit, additional caustic washes, and the like, and insome embodiments, the process does not have a water wash stepimmediately prior to the caustic wash tower or hydrogenation unit. Theintegrated process may be useful for treating the effluent of a steamcracking unit.

Olefin containing streams can be produced from various petroleumfeedstocks at high temperature by steam-cracking, fluid catalyticcracking, deep catalytic cracking processes, or the like. Olefincontaining streams can also be can be produced from oxygenates, such asalcohols, or combustion gases such as syngas. Synthesis gas can beproduced using a combustion reaction of natural gas, such as methane,and an oxygen source to produce hydrogen, carbon monoxide, and/or carbondioxide. Syngas production processes are well known and includeconventional steam reforming, autothermal reforming or a combinationthereof.

In fluid catalytic cracking (FCC) processes, a preheated hydrocarbonfeedstock of a high boiling point range can be brought into contact witha hot cracking catalyst in a catalytic cracking reactor, usually ariser. The feed is cracked into lower boiling products, such as dry gas,liquefied petroleum gas, gasoline, and various oil fractions.Furthermore, coke and non-volatile products deposit on the catalystresulting in a spent catalyst. The reactor exits into a separatorwherein the spent catalyst is separated from the reaction products. Thespent catalyst can then be stripped with steam to remove thenon-volatile hydrocarbon products from the catalyst. The strippedcatalyst can be sent to a regenerator in which coke and remaininghydrocarbon materials are combusted in the presence of oxygen and theresulting heat of combustion can be used to heat the catalyst to atemperature required for the cracking reactions. The hot, regeneratedcatalyst can be returned to the reactor for further cracking reactions.The resulting products can then be separated into a plurality of productstreams using various separation trains. Some of the products can befurther subjected to various processes and/or steps to further convertthe products into upgraded product streams.

Within these various processes, byproducts such as alkynes (e.g.,acetylene, methyl acetylene, etc.), diolefins, hydrogen, paraffins, andoxygen containing compounds such as carbon monoxide, oxygen, nitricoxide, ethers, esters, acids, carbonyls, and the like can also beproduced. When combined with diolefins, the oxygen containing compoundscan form various compounds that can foul various separators, and in someinstances, form explosive gums that can lead to safety issues withoperation of a facility. The composition and amount of these compoundsdepends on the type of the conversion treatment, and these can beremoved prior to introducing the product streams to various downstreamtreatments to avoid poisoning various catalysts (e.g., hydrogenationcatalysts, polymerization catalysts, etc.).

In some embodiments, the product streams can comprise one or more acidgases or components such as sulfur compounds (e.g., hydrogen sulfide,sulfur oxides, thiols, etc.), carbon dioxide, nitric oxides, and thelike. When sulfur is present, the sulfur can poison noble metal basedhydrogenation catalysts such as platinum, palladium, or other Group VIIImetals. Rather than using these types of catalysts, various sulfidedcatalysts that can tolerate the presence of sulfur within certainconcentration ranges can be used to hydrogenate the oxygenates and otherbyproduct compounds. The use of a hydrogenation process with a productstream comprises sulfur compounds and/or oxygenates can result in thegeneration of acid gas components such as carbon dioxide and hydrogensulfide, which can be removed in an acid gas removal process. One suchprocess includes a caustic wash cycle.

As disclosed herein, a sulfided catalyst can be used to hydrogenate andremove various byproducts including oxygen containing compounds in aproduct stream from one or more cracking process. In general, theproduct stream can comprise a dry gas stream having heavier condensablecomponents removed. The hydrogenation process using the sulfidedcatalyst can be integrated between two loops of a caustic wash process.The placement of the hydrogenation process between the caustic washloops may allow an upstream water wash to be removed or eliminated fromthe process. This process configuration may also reduce the need forguard beds to remove various components such as arsine, phosphine,mercury, carbonyl sulfide, water, carbon dioxide, nitrogen oxides, andsulfur compounds that can be associated with a hydrogenation processusing a Group VIII metal. Even if these processes and guard beds arepresent, their size can be reduced based on the process comprising thehydrogenation process using the sulfided catalyst located between thecaustic wash loops.

FIG. 1 schematically illustrates a process flow diagram of a system 100for removing oxygen containing compounds from a product stream. As shownin FIG. 1, a hydrocarbon processing unit 101 may initially generate aproduct stream containing various hydrocarbons such as methane, ethane,olefins (e.g., ethylene, propylene, etc.), and one or more byproducts orcontaminants such as oxygen containing compounds and sulfur or sulfurcompounds.

The hydrocarbon processing unit 101 can comprise any of the reforming orcracking processes described herein including FCC, steam cracking, deepcatalytic cracking processes, or the like. Additional processes capableof producing a product stream comprising acid gas components and/orsulfur can form a part of the hydrocarbon processing unit 101. Otherprocessing units such as synthesis gas units, a methanol-to-olefinreactor, or the like can be present and produce a product stream thatcan be hydrogenated in the process described herein.

In some embodiments, the hydrocarbon processing unit 101 can comprise anFCC unit 102 producing a first product stream in line 103. The FCCproduct stream can comprise a number of components that can be furtherupgraded in a stream cracking unit 106. While the entire FCC productstream can be sent to the steam cracking unit 106, some embodiments mayfirst separate the FCC product stream in line 103 into a variety ofstreams. The FCC product stream may be separated in a separation unit104 into a dry gas stream and at least one other product stream such asa fuel oil stream, a naphtha stream, and/or other product streams. Forexample, the FCC product stream can be compressed and cooled to condenseand separate one or more fractions from the FCC product stream. The drygas stream generally comprises the non-condensable components of the FCCproduct stream such as hydrogen, methane, ethane, propane, and variouscontaminants such as oxygen containing compounds (e.g., carbon monoxide,carbon dioxide, etc.) and sulfur or sulfur compounds (e.g., hydrogensulfide, sulfur oxides, thiols, etc.). While two separate product linesin addition to line 105 are shown leaving the separation unit 104 inFIG. 1, any number of product streams can be separated and produced fromthe separation unit 104.

The dry gas stream can pass through line 105 to the steam cracking unit106. Within the steam cracking unit 106, the dry gas can be combinedwith high temperature, high pressure steam to cause a conversion of aportion of the methane, ethane, and any propane into ethylene andpropylene along with various oxygenated compounds and other acid gases.Oxygen can be introduced through the use of steam to generate additionaloxygen containing compounds in the steam cracking unit 106. Since onlythe dry gas may be passed to the steam cracking unit 106, the acid gascomponents may not be removed from the dry gas prior to the dry gaspassing to the steam cracking unit 106 for processing.

In some embodiments, the hydrocarbon processing unit 101 can compriseany number of FCC, steam cracking, or other processing units, and theunits can be arranged in series or parallel. For example, the FCCproduct stream can be combined with a steam cracking unit product streamprior to passing to the downstream processing units.

The resulting product stream in line 107 can comprise the products fromthe hydrocarbon processing unit 101. In some embodiments, an optionalquenching unit 108 may be used to cool the product stream to a desiredtemperature and/or remove any solids (e.g., FCC catalyst fines, etc.) orentrained liquids prior to passing the product stream to the acid gasremoval unit 110. While a quenching unit 108 is shown in FIG. 1, anysuitable unit or process for cooling the process stream such as a heatexchanger or the like can be used to reduce the temperature of theproduct stream in line 109 to a desired temperature.

The hydrocarbon product stream in line 109 can have an acid gasconcentration and/or sulfur concentration that could poison a group VIIImetal hydrogenation catalyst. In an embodiment, the hydrocarbon productstream can have a sulfur content of between about 1 ppm to about 1,000ppm by weight, between about 5 ppm and about 250 ppm by weight. In someembodiments, the hydrocarbon product stream in line 109 can have asulfur content greater than about 50 ppm, greater than about 60 ppm,greater than about 70 ppm, or greater than about 80 ppm, each by weight.

The acid gas removal unit 110 can comprise any suitable unit forremoving at least a portion of the acid gases present in the productstream from the hydrocarbon processing unit 101. The acid gas removalunit 110 can serve to remove acid gases such as carbon dioxide andhydrogen sulfide. Solid or liquid acid gas treatment systems can be usedin this acid gas removal unit 110. In these types of units, the acid gascan be removed from the product stream by contacting the product streamwith an acid gas absorbent or adsorbent. Examples of such-absorbents oradsorbents include amines, potassium carbonate, caustic, alumina,molecular sieves and membranes, particularly membranes formed ofpolysulfone, polyimide, polyamide, glassy polymer and cellulose acetate.Caustic compounds suitable for use in the acid gas removal unit caninclude alkaline compounds, which are effective in removing acid gasfrom a hydrocarbon containing product stream such as various hydroxides(e.g., sodium hydroxide, potassium hydroxide, etc.). When a causticsolution is used as described herein, the caustic solution can have aconcentration from about 1% to about 30% by weight, or from about 2% toabout 20% by weight.

In an embodiment, the acid gas removal unit 110 can comprise a causticwash tower having a plurality of wash loops. In an embodiment, thecaustic wash tower can comprise a packed column, although a plateabsorption column may also be used. The absorbent liquid (the alkalinesolution) can be evenly distributed across the top of the column using adistributor plate, spray nozzles, or the like. At the bottom of theabsorption column is a gas inlet where product stream containing theoxygen containing compounds and acid gases can enter the absorptioncolumn. The vapor components can move up the column countercurrent tothe liquid absorbent moving down the column in a countercurrentabsorption process. The packing or plates in the column provides asurface for contact between the vapor and liquid components within thecolumn. In a countercurrent absorption column, the concentration ofsoluble gasses in both the liquid and vapor phases is greatest at thebottom of the column, and lowest at the top of the column. The outletfor the liquid is at or near the bottom of the absorption column,typically below the gas inlet. The outlet for the gas phase lean in theacid gasses most soluble in the liquid absorbent is at the top of theabsorption column, typically above the liquid inlet. The caustic washtower can operate at any pressure, and may generally operate at apressure slightly below the pressure of the olefin-containinghydrocarbon stream. The temperature within the caustic wash tower isselected so that the alkaline solution remains in the liquid state.

In an embodiment, the acid gas removal process can comprise a pluralityof loops 112, 114, 116. The concentration of the caustic solution withineach loop can vary in order to effect the removal of the acid gascomponents. The loops can represent individual caustic wash towersarranged in series, or a series of caustic wash zones within one or morecaustic wash towers using, for example, collection trays, side draws,pump arounds, caustic makeup stream, and the like at various locationswithin the column. As schematically shown in FIG. 1, three caustic washloops 112, 114, 116 can be present, with the hydrocarbon product streamin line 109 passing through each of the caustic wash loops 112, 114, 116in series. While three caustic wash loops 112, 114, 116 are shown, onlytwo caustic wash loops or more than three caustic wash loops may bepresent.

When three caustic wash loops are present, the concentration of thecaustic solution used in each caustic wash loop 112, 114, 116 cangenerally increase from the first caustic wash loop 112 to the secondcaustic wash loop 114, and further increase from the second caustic washloop 114 to the third caustic wash loop 116. For example, the causticsolution in the first caustic wash loop 112 can have a causticconcentration between about 0.5% and about 10% by weight, or betweenabout 1% to about 3% by weight. The caustic solution in the secondcaustic wash loop 114 can have a caustic concentration between about 5%and about 15% by weight, or between about 8% and about 12% by weight.The caustic solution in the third caustic wash loop 116 can have acaustic concentration between about 15% and about 25% by weight, orbetween about 18% and about 22% by weight.

As shown in FIG. 1, a hydrogenation process can be carried out in ahydrogenation unit 122 between two of the caustic wash loops 112, 114 ofa multi-loop caustic wash unit 110. When the hydrogenation reactor isbetween the first caustic wash loop 112 and the second caustic wash loop114, the hydrocarbon product stream in line 109 can pass through thefirst caustic wash loop 112 before passing through line 113 to thehydrogenation unit 122. The products from the hydrogenation unit 122 canthen pass through line 115 to the second caustic wash loop 114. In someembodiments, the gaseous stream from the second caustic wash loop 114can then pass to the third caustic wash loop 116 before passing out ofthe acid gas removal unit 110 through line 130.

In some embodiments, the hydrogenation unit can be located between thesecond and third caustic wash loops. In this embodiment, the hydrocarbonproduct stream in line 109 can pass through the first caustic wash loop112 before passing to the second caustic wash loop 114. The gaseousproducts from the second caustic wash loop 114 can then pass throughline 117 to the hydrogenation unit 124. The products from thehydrogenation unit 124 can then pass through line 119 to the thirdcaustic wash loop 116. The gaseous stream from the third caustic washloop 116 can then pass out of the acid gas removal unit 110 through line130. In general, the hydrogenation unit will only be present in onelocation between two of the caustic wash loops. In some embodiments,multiple hydrogenation units can be present, such that, for example,both hydrogenation unit 122 and hydrogenation unit 124 are present inthe system 100.

The hydrogenation unit 122 can hydrogenate various components includingalkynes, oxygen containing compounds, and sulfur containing compounds toallow the components to be converted to more easily removable compoundssuch as carbon dioxide, hydrogen sulfide, and the like. These compoundscan be hydrogenated over a sulfided catalyst such as a sulfided copperor sulfided nickel catalyst. In an embodiment, the catalyst can comprisea sulfided nickel catalyst. Other sulfided catalysts could also be usedsuch as sulfides of zinc, copper, gallium, cadmium, chromium,molybdenum, tungsten, cobalt, nickel, ruthenium, iron, and any mixturesthereof. The catalyst can be suitably formed and/or supported on varioussupports including, for example, the silica or alumina, with or withouta promoter metal is well known in the art. In order to effect thehydrogenation, the hydrocarbon product stream can contain or be mixedwith an excess of hydrogen or hydrogen rich gas over the hydrogenationcatalyst under suitable hydrogenation conditions.

The hydrogenation unit 122 can tolerate sulfur in the process stream,but the level of sulfur may need to be controlled. In an embodiment, thehydrogenation can be carried out with the sulfur level in the stream inline 113 reduced to less than about 80 ppm, less than about 70 ppm, lessthan about 60 ppm, or less than about 50 ppm by weight. Theconcentration and conditions in the first caustic wash loop 112 can beconfigured to reduce the sulfur content in the hydrocarbon productstream in line 109 to a level suitable for hydrogenating the stream inthe hydrogenation unit 122. For example, any acid gas components such ashydrogen sulfide in the hydrocarbon product stream in line 109 can be atleast partially removed in the first caustic wash loop 112 to reduce thetotal sulfur concentration to below an operating threshold for thesulfided catalyst. The resulting acid gas components from thehydrogenation unit 122 can then be removed in the downstream causticwash loops in the acid gas removal unit 110.

The hydrogenation unit 122 and/or the hydrogenation unit 124 can removeat least about 80%, at least about 90%, at least about 95%, at leastabout 97%, at least about 98%, or at least about 99% of the oxygencontaining compounds and sulfur/sulfur compounds from the hydrocarbonstream entering the hydrogenation unit. The downstream caustic washloops can then effectively remove at least about 80%, at least about90%, at least about 95%, at least about 97%, or at least about 98% ofthe acid gas components produced in the hydrogenation unit 122 and/orthe hydrogenation unit 124. The resulting hydrocarbon stream in line 130may then have a reduced level of byproducts, oxygen containingcompounds, and sulfur as compared to the hydrocarbon product stream inline 109. Further, the integration of the hydrogenation unit 122 and/orhydrogenation unit 124 with the caustic wash system may reduce thenumber of wet scrubbing processes required upstream and/or downstream ofthe integrated hydrogenation unit/caustic wash unit when compared toother processes in which the hydrogenation unit using a sulfidedcatalyst is not integrated with the acid gas removal unit 110.

Following acid gas removal unit 110, the hydrocarbon stream in line 130can be further treated using various downstream processing units. Insome embodiments, the hydrocarbon stream in line 130 may be dried usingan optional water removal unit 131 including a desiccant dryer, amolsieve dryer, absorbents, or the like to provide a substantially drystream, which may help to prevent the formation of ice or hydrates inany subsequent cryogenic distillation recovery systems.

In some embodiments, an additional hydrogenation step can be carried outdownstream of the integrated acid gas removal unit 110 and hydrogenationunit 122 and/or hydrogenation unit 124, depending on the presence ofvarious components in the hydrocarbon stream in line 130.

The dried gas can then be sent to a downstream separation unit 132 toseparate the hydrocarbon stream into one or more product streams. Theseparation unit 132 can include any number of suitable separators orseparation trains to produce a plurality of product streams (e.g., passthrough outlet lines 134, 136, etc.). Typical product streams caninclude one or more of a light gas stream comprising hydrogen and/ormethane, an ethane stream, an ethylene stream, a propylene stream, andpotentially additional streams depending on the makeup of thehydrocarbon stream entering the separation unit 132.

Having described numerous devices, systems, and methods herein, variousembodiments can include, but are not limited to:

In a first embodiment, a method of removing oxygenates from ahydrocarbon stream comprises passing a hydrocarbon stream to a caustictower, wherein the hydrocarbon stream comprises one or morehydrocarbons, one or more oxygen containing components, and one or moresulfur containing compounds, and wherein the caustic tower comprises aplurality of loops, contacting the hydrocarbon stream with a sulfidedcatalyst between a first loop of the plurality of loops and a secondloop of the plurality of loops to produce a reaction product, wherein atleast a portion of the one or more sulfur containing compounds react inthe presence of the sulfided catalyst to produce hydrogen sulfide in thereaction product, passing the reaction product to the second loop,removing at least a portion of the hydrogen sulfide in the second loopof the caustic tower to produce a product stream, and separating theproduct stream into a plurality of hydrocarbon streams in a separationzone located downstream of the caustic tower.

A second embodiment can include the method of the first embodiment,further comprising: producing the hydrocarbon stream in a crackingprocess, wherein the cracking process comprises at least one of a fluidcatalytic cracking process, a steam cracking process, or a deepcatalytic cracking process.

A third embodiment can include the method of the second embodiment,wherein producing the hydrocarbon stream comprises: producing a firstproduct stream in a fluid catalytic cracking process; separating thefirst product stream to obtain a dry gas stream from the first productstream; passing the dry gas stream to a steam cracking unit; andcracking the dry gas stream in the steam cracking unit to produce thehydrocarbon stream.

A fourth embodiment can include the method of any of the first to thirdembodiments, wherein the hydrocarbon stream comprises a sulfurconcentration of greater than about 80 ppm by weight.

A fifth embodiment can include the method of the fourth embodiment,further comprising: reducing the sulfur concentration of the hydrocarbonstream to less than about 80 ppm by weight in the first loop of thecaustic tower prior to contacting the hydrocarbon stream with thesulfided catalyst.

A sixth embodiment can include the method of any of the first to fifthembodiments, wherein the sulfided catalyst comprises nickel sulfide.

A seventh embodiment can include the method of any of the first to sixthembodiments, wherein the first loop uses a caustic solution having acaustic concentration of between about 0.5% and about 10%.

An eighth embodiment can include the method of any of the first toseventh embodiments, wherein at least a portion of the one or moreoxygen containing components react in the presence of the sulfidedcatalyst to produce carbon dioxide in the reaction product, and whereinthe method further comprises removing at least a portion of the carbondioxide in the second loop of the caustic tower.

A ninth embodiment can include the method of any of the first to eighthembodiments, wherein the hydrocarbon stream comprises an olefin.

A tenth embodiment can include the method of any of the first to ninthembodiments, wherein the product stream comprises hydrogen, methane,ethane, propane, butane, ethylene, propylene, butene, or any combinationthereof.

In an eleventh embodiment, a system for removing oxygenates from ahydrocarbon stream comprises a caustic wash unit comprising a pluralityof caustic wash loops; and a hydrogenation reactor configured to receivea first gaseous stream from a first caustic wash loop of the pluralityof caustic wash loops and pass a second gaseous stream from thehydrogenation reactor to a second caustic wash loop of the plurality ofcaustic wash loops, wherein the hydrogenation reactor comprises asulfided catalyst.

A twelfth embodiment can include the system of the eleventh embodiment,further comprising: a cracking unit configured to convert one or morehydrocarbons to lighter products, wherein the cracking unit is fluidlycoupled to the caustic wash unit and is arranged upstream of the causticwash unit.

A thirteenth embodiment can include the system of the twelfthembodiment, wherein the cracking unit comprises a fluid catalyticcracking unit, a steam cracking unit, or any combination thereof.

A fourteenth embodiment can include the system of the twelfth orthirteenth embodiment, wherein the cracking unit comprises: a fluidcatalytic cracking unit; a separation unit fluidly coupled to the fluidcatalytic cracking unit and configured to receive a first product streamfrom the fluid catalytic cracking unit and separate a dry gas streamfrom the first product stream; and a steam cracking unit fluidly coupledto the separation unit and configured to receive the dry gas stream fromthe separation unit.

A fifteenth embodiment can include the system of any of the eleventh tofourteenth embodiments, wherein the sulfided catalysts comprises asulfide of nickel, zinc, copper, gallium, cadmium, chromium, molybdenum,tungsten, cobalt, ruthenium, iron, or any mixtures thereof.

A sixteenth embodiment can include the system of any of the eleventh tofifteenth embodiments, further comprising: a dryer fluidly coupled tothe caustic wash unit, wherein the dryer is configured to receive agaseous product stream from the caustic wash unit and remove at least aportion of the water in the gaseous product stream.

A seventeenth embodiment can include the system of any of the eleventhto sixteenth embodiments, further comprising: a separation unit fluidcoupled to the caustic wash unit, wherein the separation unit isdisposed downstream of the caustic wash unit, and wherein the separationunit is configured to receive a gaseous product stream from the causticwash unit and separate the gaseous product stream into a plurality ofproduct streams.

In an eighteenth embodiment, a method of removing oxygenates from ahydrocarbon stream comprises passing a hydrocarbon stream to a firstloop of a caustic tower, wherein the hydrocarbon stream comprises one ormore hydrocarbons, one or more oxygen containing components, and one ormore acid gas components; removing a portion of the one or more acid gascomponents in the first loop of the caustic tower to produce a firstproduct stream; passing the first product stream from the first loop ofthe caustic tower to a hydrogenation unit; contacting the first productstream with a sulfided catalyst in the hydrogenation unit to produce asecond product stream, wherein at least a portion of the one or moresulfur containing compounds react in the presence of the sulfidedcatalyst to produce hydrogen sulfide in the reaction product; passingthe second product stream to a second loop of the caustic tower, andremoving at least a portion of the hydrogen sulfide in the second loopof the caustic tower to produce a third product stream.

A nineteenth embodiment can include the method of the eighteenthembodiment, further comprising: contacting a hydrocarbon feed streamwith a catalyst in a fluid catalytic cracking unit; generating a productstream comprising olefins in the fluid catalytic cracking unit;separating the product stream to produce a dry gas stream, wherein thedry gas stream comprises at least a portion of the olefins; passing thedry gas stream to a steam cracking unit; generating the hydrocarbonstream in the steam cracking unit; and passing the hydrocarbon stream tothe caustic tower.

A twentieth embodiment can include the method of the nineteenthembodiment, further comprising: separating the third product stream intoa plurality of hydrocarbon streams in a separation system locateddownstream of the caustic tower.

While various embodiments in accordance with the principles disclosedherein have been shown and described above, modifications thereof may bemade by one skilled in the art without departing from the spirit and theteachings of the disclosure. The embodiments described herein arerepresentative only and are not intended to be limiting. Manyvariations, combinations, and modifications are possible and are withinthe scope of the disclosure. Alternative embodiments that result fromcombining, integrating, and/or omitting features of the embodiment(s)are also within the scope of the disclosure. Accordingly, the scope ofprotection is not limited by the description set out above, but isdefined by the claims which follow, that scope including all equivalentsof the subject matter of the claims. Each and every claim isincorporated as further disclosure into the specification and the claimsare embodiment(s) of the present invention(s). Furthermore, anyadvantages and features described above may relate to specificembodiments, but shall not limit the application of such issued claimsto processes and structures accomplishing any or all of the aboveadvantages or having any or all of the above features.

Additionally, the section headings used herein are provided forconsistency with the suggestions under 37 C.F.R. 1.77 or to otherwiseprovide organizational cues. These headings shall not limit orcharacterize the invention(s) set out in any claims that may issue fromthis disclosure. Specifically and by way of example, although theheadings might refer to a “Field,” the claims should not be limited bythe language chosen under this heading to describe the so-called field.Further, a description of a technology in the “Background” is not to beconstrued as an admission that certain technology is prior art to anyinvention(s) in this disclosure. Neither is the “Summary” to beconsidered as a limiting characterization of the invention(s) set forthin issued claims. Furthermore, any reference in this disclosure to“invention” in the singular should not be used to argue that there isonly a single point of novelty in this disclosure. Multiple inventionsmay be set forth according to the limitations of the multiple claimsissuing from this disclosure, and such claims accordingly define theinvention(s), and their equivalents, that are protected thereby. In allinstances, the scope of the claims shall be considered on their ownmerits in light of this disclosure, but should not be constrained by theheadings set forth herein.

Use of broader terms such as “comprises,” “includes,” and “having”should be understood to provide support for narrower terms such as“consisting of,” “consisting essentially of,” and “comprisedsubstantially of.” Use of the term “optionally,” “may,” “might,”“possibly,” and the like with respect to any element of an embodimentmeans that the element is not required, or alternatively, the element isrequired, both alternatives being within the scope of the embodiment(s).Also, references to examples are merely provided for illustrativepurposes, and are not intended to be exclusive.

While several embodiments have been provided in the present disclosure,it should be understood that the disclosed systems and methods may beembodied in many other specific forms without departing from the spiritor scope of the present disclosure. The present examples are to beconsidered as illustrative and not restrictive, and the intention is notto be limited to the details given herein. For example, the variouselements or components may be combined or integrated in another systemor certain features may be omitted or not implemented.

Also, techniques, systems, subsystems, and methods described andillustrated in the various embodiments as discrete or separate may becombined or integrated with other systems, modules, techniques, ormethods without departing from the scope of the present disclosure.Other items shown or discussed as directly coupled or communicating witheach other may be indirectly coupled or communicating through someinterface, device, or intermediate component, whether electrically,mechanically, or otherwise. Other examples of changes, substitutions,and alterations are ascertainable by one skilled in the art and could bemade without departing from the spirit and scope disclosed herein.

1. A method of removing oxygenates from a hydrocarbon stream, the methodcomprising: passing a hydrocarbon stream to a caustic tower, wherein thehydrocarbon stream comprises one or more hydrocarbons, one or moreoxygen containing components, and one or more sulfur containingcompounds, and wherein the caustic tower comprises a plurality of loops;contacting the hydrocarbon stream with a sulfided catalyst between afirst loop of the plurality of loops and a second loop of the pluralityof loops to produce a reaction product, wherein at least a portion ofthe one or more sulfur containing compounds react in the presence of thesulfided catalyst to produce hydrogen sulfide in the reaction product;passing the reaction product to the second loop; removing at least aportion of the hydrogen sulfide in the second loop of the caustic towerto produce a product stream; and separating the product stream into aplurality of hydrocarbon streams in a separation zone located downstreamof the caustic tower.
 2. The method of claim 1, further comprising:producing the hydrocarbon stream in a cracking process, wherein thecracking process comprises at least one of a fluid catalytic crackingprocess, a steam cracking process, or a deep catalytic cracking process.3. The method of claim 1, wherein producing the hydrocarbon streamcomprises: producing a first product stream in a fluid catalyticcracking process; separating the first product stream to obtain a drygas stream from the first product stream; passing the dry gas stream toa steam cracking unit; and cracking the dry gas stream in the steamcracking unit to produce the hydrocarbon stream.
 4. The method of claim1, wherein the hydrocarbon stream comprises a sulfur concentration ofgreater than about 80 ppm by weight.
 5. The method of claim 4, furthercomprising: reducing the sulfur concentration of the hydrocarbon streamto less than about 80 ppm by weight in the first loop of the caustictower prior to contacting the hydrocarbon stream with the sulfidedcatalyst.
 6. The method of claim 1, wherein the sulfided catalystcomprises nickel sulfide.
 7. The method of claim 1, wherein the firstloop uses a caustic solution having a caustic concentration of betweenabout 0.5% and about 10%.
 8. The method of claim 1, wherein at least aportion of the one or more oxygen containing components react in thepresence of the sulfided catalyst to produce carbon dioxide in thereaction product, and wherein the method further comprises removing atleast a portion of the carbon dioxide in the second loop of the caustictower.
 9. The method of claim 1, wherein the hydrocarbon streamcomprises an olefin.
 10. The method of claim 1, wherein the productstream comprises hydrogen, methane, ethane, propane, butane, ethylene,propylene, butene, or any combination thereof.
 11. A system for removingoxygenates from a hydrocarbon stream, the system comprising: a causticwash unit comprising a plurality of caustic wash loops; and ahydrogenation reactor configured to receive a first gaseous stream froma first caustic wash loop of the plurality of caustic wash loops andpass a second gaseous stream from the hydrogenation reactor to a secondcaustic wash loop of the plurality of caustic wash loops, wherein thehydrogenation reactor comprises a sulfided catalyst.
 12. The system ofclaim 11, further comprising: a cracking unit configured to convert oneor more hydrocarbons to lighter products, wherein the cracking unit isfluidly coupled to the caustic wash unit and is arranged upstream of thecaustic wash unit.
 13. The system of claim 12, wherein the cracking unitcomprises a fluid catalytic cracking unit, a steam cracking unit, or anycombination thereof.
 14. The system of claim 12, wherein the crackingunit comprises: a fluid catalytic cracking unit; a separation unitfluidly coupled to the fluid catalytic cracking unit and configured toreceive a first product stream from the fluid catalytic cracking unitand separate a dry gas stream from the first product stream; and a steamcracking unit fluidly coupled to the separation unit and configured toreceive the dry gas stream from the separation unit.
 15. The system ofclaim 11, wherein the sulfided catalyst comprises a sulfide of nickel,zinc, copper, gallium, cadmium, chromium, molybdenum, tungsten, cobalt,ruthenium, iron, or any mixtures thereof.
 16. The system of claim 11,further comprising: a dryer fluidly coupled to the caustic wash unit,wherein the dryer is configured to receive a gaseous product stream fromthe caustic wash unit and remove at least a portion of the water in thegaseous product stream.
 17. The system of claim 11, further comprising:a separation unit fluidly coupled to the caustic wash unit, wherein theseparation unit is disposed downstream of the caustic wash unit, andwherein the separation unit is configured to receive a gaseous productstream from the caustic wash unit and separate the gaseous productstream into a plurality of product streams.
 18. A method of removingoxygenates from a hydrocarbon stream, the method comprising: passing ahydrocarbon stream to a first loop of a caustic tower, wherein thehydrocarbon stream comprises one or more hydrocarbons, one or moreoxygen containing components, and one or more acid gas components;removing a portion of the one or more acid gas components in the firstloop of the caustic tower to produce a first product stream; passing thefirst product stream from the first loop of the caustic tower to ahydrogenation unit; contacting the first product stream with a sulfidedcatalyst in the hydrogenation unit to produce a second product stream,wherein at least a portion of the one or more sulfur containingcompounds react in the presence of the sulfided catalyst to producehydrogen sulfide in the second product stream; passing the secondproduct stream to a second loop of the caustic tower; and removing atleast a portion of the hydrogen sulfide in the second product stream inthe second loop of the caustic tower to produce a third product stream.19. The method of claim 18, further comprising: contacting a hydrocarbonfeed stream with a catalyst in a fluid catalytic cracking unit;generating a product stream comprising olefins in the fluid catalyticcracking unit; separating the product stream to produce a dry gasstream, wherein the dry gas stream comprises at least a portion of theolefins; passing the dry gas stream to a steam cracking unit; generatingthe hydrocarbon stream in the steam cracking unit; and passing thehydrocarbon stream to the caustic tower.
 20. The method of claim 19,further comprising: separating the third product stream into a pluralityof hydrocarbon streams in a separation system located downstream of thecaustic tower.